Proper use of blowout preventers during well drilling and servicing operations is necessary to conserve oil and gas, prevent pollution of the environment, minimize danger of explosion of combustile fuel, control downhole pressure, and minimize waste of mud and other expensive materials circulated through the well.
Hydraulically actuated blowout preventers are of two basic types well known to persons skilled in the art, namely annular preventers and ram preventers. Each type of blowout preventer requires delivery of pressurized hydraulic fluid into and out of opening and closing chambers to control force urging seal elements into sealing relation with drill pipe, tubing or a wireline extending through a casing or to move seal elements into sealing relation with each other to close off an open hole.
Control systems are sometimes required to deliver hydraulic fluid at a pressure of 1,500 psi to opening and closing chambers of annular preventers and to hold the closing pressure on the preventer in case of an emergency.
Closing pressure of hydraulic fluid required for closing ram preventers is generally less than pressure required for closing annular preventers. Closing pressure for ram preventers is generally about 750 psi. However, closing pressure is dictated by the design criteria of the manufacturer.
When stripping drill pipe or tubing into or out of a well, pressure less than that required for closing a preventer is generally employed to permit movement of the pipe without causing excessive wear on the seal elements in the preventer.
Manually actuated control valves have been installed heretofore in a main control panel a substantial distance from the rig floor, for example, at the far end of the pipe rack, from which hydraulic fluid was controlled for actuation of blowout preventers. Remote closing units generally have been mounted on the floor of the drilling rig near the drillers position, for example, by the exit the driller would use when leaving the rig floor. Remote closing units, located remotely from the main control panel, generally have comprised a switch for actuating a solenoid valve through which pressurized fluid was delivered to hydraulic actuating cylinder connected to the control valve at the main control panel. Other remote closing units have consisted of valves which control the flow of compressed air to an actuating cylinder associated with the control valve at the main control panel.
When the driller on the drilling floor of a typical drilling rig actuated an air valve on the remote control panel, air supplied to the panel by rig air would flow through an air hose bundle and through the air circuitry to an air cylinder. The air cylinder was attached to the manual lever on a four-way hydraulic control valve. The air cylinder pushed the manual lever and opened or closed the four-way hydraulic control valve. Fluid flowing from the four-way hydraulic control valve through the hydraulic circuitry passed through control lines some distance, usually 100 feet or more, to blowout preventers which were usually a hydraulic cylinder arrangement. When the fluid was applied through the control lines, the preventers would close around whatever was in the hole, usually drill pipe.
Each four-way hydraulic control valve required two control lines, one connected to each end of the hydraulic cylinder which actuated a blowout preventer. On modern systems, this requires piping to run from the power unit to every function located some distance away. It also requires that all remote actuation, such as on the driller's panel or other remote units, run through air hose bundles back to the power unit where the four-way hydraulic control valves are located.
Thus, blowout preventer control systems heretofore devised required long runs of pipe between power units and blowout preventers. The driller could not manually actuate the four-way hydraulic control valves, and therefore, was required to depend upon the availability of air or electrical actuators to control blowout preventers from the rig floor. Further, in some installations, blowout preventer control systems have not been adequately protected from heavy equipment used at and around the well site.
Heretofore, the blowout preventer stack has been higher in vertical distance from the ground than have been the four-way hydraulic control valves located at the main control panel. Thus, fluid would flow back to the main control valves. Each time a function was actuated, the response time was increased by having to refill empty lines.
Blowout preventer control systems, heretofore devised, have not been easily adaptable for use in climates of extremely low temperature.